Hydraulic fracturing or “fracking” is the propagation of fractures in a rock layer by a pressurized fluid. The oil and gas industry uses hydraulic fracturing to enhance subsurface fracture systems to allow oil or natural gas to drain more freely from the reservoir to production wells that bring the oil or gas to the surface. However, there many uses for hydraulic fracturing outside of the petroleum industry, including to stimulate groundwater wells, to precondition rock for cave in mining, to enhance waste remediation processes, to dispose of waste by injection into deep rock formations, including CO2 sequestration, to measure the stress in the earth, and for heat extraction in geothermal systems.
In hydraulic fracking, an injection fluid, usually including water or brine and a polymer and/or sand, is injected into a reservoir at pressures high enough to fracture the rock. The two main purposes of fracturing fluid or “frack fluid” in oil reservoirs is to extend fractures in the reservoir and to carry proppants, such as grains of sand, into the formation, the purpose of which is to hold the fractures open without damaging the formation or production from the well. The purpose of the polymer is to thicken the frack fluid, allowing it to more effectively carry the proppant deeper into the reservoir.
Without fracking, the time needed to drain a field would be inordinately long—in a tight field it could be in the order of hundreds of years. The only way to drain the oil in a reasonable time is to drill more wells—e.g., up to 40 wells per square mile in a tight field—a very expensive undertaking, or to fracture the field. The existence of long fractures allows the fields to be drained in a reasonable time period, with fewer wells, and in a more cost effective way.
Since Stanolind Oil introduced hydraulic fracturing in 1949, close to 2.5 million fracture treatments have been performed worldwide. Some believe that approximately 60% of all wells drilled today are fractured. Fracture stimulation not only increases the production rate, but it is credited with adding to reserves-9 billion bbl of oil and more than 700 Tscf of gas added since 1949 to US reserves alone—which otherwise would have been uneconomical to develop. In addition, through accelerating production, net present value of reserves has increased.
In 1976, Othar Kiel started using high-rate “hesitation” fracturing to cause what he called “dendritic” fractures—with tree like branching patterns. The method was invented from the observation of unusually good production increases from a number of wells that had been temporarily shut in due to equipment failures. Since the two groups of wells differed primarily in a single factor—an inadvertent shut-down period—another group of wells was selected for controlled tests of this factor, and it was found that when an intentional shut-down period of one hour was put in the frack plan, the first month's production was about double!
The U.S. Pat. No. 3,933,205 Kiel patent describes the method, now known as the “Keil process” or “dendritic fracturing.” The process uses a cyclic injections to form extraordinarily long, branching flow channels. Fracking pressures induces spalling (flaking of rock fragments) from the fracture faces. When the well is shut in and then reinjected, the fluid movement moves the debris to the ends of the fractures, causing increased pressures at the end, and thus further propagating the fracture in a direction perpendicular to the initial fracture. Repeated cycles cause further branching. The transverse fractures will eventually intersect and communicate with natural fractures that parallel the direction of the primary fracture, thus a fully branched drainage system is developed. Further improvement can be had if the wells are opened for reverse flow during the shut-down period.
The Kiel method has been applied with good results to a wide range of formations at depths to 11,500 ft. Most of more than 400 dendritic (branching) fracturing jobs performed since the 70's have shown sustained productivity increases of 2-5 times those generated by conventional fracturing.
Heterogeneous proppant placement (HPP) is yet another new approach in hydraulic fracturing, invented Schlumberger Technology Corporation (U.S. Pat. No. 6,776,235). Well productivity is increased by sequentially injecting into the wellbore alternate stages of fracturing fluids having a contrast in their ability to transport propping agents to improve proppant placement, or having a contrast in the amount of transported propping agents. The propped fractures obtained following this process have a pattern characterized by a series of bundles of proppant spread along the fracture. In another words, the bundles form “pillars” that keep the fracture opens along its length and provide channels for the formation fluids to circulate.
Although fracking is quite successful, even incremental improvements in technology can mean the difference between cost effective production, and reserves that are uneconomical to produce. One area of improvement would be the possibility of assessing or even imaging the fractures in the reservoir, so that the fractures can be evaluated and the frack plan modified as needed for optimization.
Current imaging technology tends to be either expensive and time consuming to obtain or of limited value. Imaging methods include seismic imaging, microseismic imaging, both of which are expensive. Core samples can be obtained and the fractures imaged therein, but the information is limited to the core samples, plus the coring process itself tends to introduce artificial fractures. Borehole images in contrast are cheaper to acquire than core samples and can hence be acquired over longer intervals in more wells. They image the fractures in situ, showing whether they are open or closed in the subsurface. They are oriented, enabling the predominant fracture orientation(s) to be determined. However, core and borehole image analysis in 1D cannot directly measure fracture length or connectivity—key controls on fracture permeability. 2D outcrop analogue mapping can measure fracture length or connectivity, yet the outcrop data may inaccurately predict in situ results.
What is needed in the art are better methods of ascertaining the fracture patterns of reservoirs.